FERC said Wednesday that ITC Midwest can keep the capital structure it has had in place since 2007, blocking an Alliant Energy-led complaint in the process (EL22-56).
Alliant’s coalition of Iowa utilities, industrial customers and consumer advocates in May challenged ITC’s capital structure as excessive and too skewed toward equity. They asked the commission to reduce ITC’s equity ratio to 53% and establish hearing and settlement procedures to grant refunds to transmission customers. (See Alliant Energy Leads Challenge of ITC Midwest Capital Structure.)
ITC Midwest, an independent transmission company, uses a capital structure reflecting 60% equity and 40% debt in its formula rate to calculate its overall rate of return.
FERC said the coalition did not prove that the utility’s existing capital structure is unjust and unreasonable. It ruled that ITC’s target capital structure is comparable with those used by other investor-owned MISO transmission owners and is not unusually high.
The commission also pointed to its policy of using the actual capital structure “of the entity that provides the financing, whether that entity is the utility or its parent company.”
Iowa customers argued that FERC’s approval of ITC’s 60% target equity ratio 15 years ago was “based on the expectation that ITC Midwest would have its own credit rating separate from its parent company,” ITC Holdings. They argued that both the utility and MISO have undergone seismic changes since the capital structure was approved, with ITC Midwest’s rate base increasing 550% since 2008 and ITC Holdings being acquired by Fortis, Inc.
Both the Iowa Utilities Board and the Minnesota Department of Commerce intervened at FERC in support of the complaint.
However, the commission said the Iowa customers didn’t establish that either ITC Holdings or Fortis guarantees ITC Midwest’s debt or that they would assume its debt obligations if the utility defaulted. FERC also said that contrary to allegations, ITC Midwest has a different bond rating from ITC Holdings and Fortis.
“Although ITC Midwest does not have its own management-level employees and relies on ITC Holdings’ management, this does not demonstrate that ITC Holdings guarantees ITC Midwest’s long-term debt,” FERC said.
With winter heating bills on the way, the Biden administration on Wednesday announced nearly $9 billion in funding from the Inflation Reduction Act to provide rebates to families for upgrading their homes with a range of energy-efficient improvements.
Announcing the new funding to a cheering crowd at a Sheet Metal Workers Union hall in Boston. Vice President Kamala Harris said the $146 million coming to Massachusetts will provide “rebates of more than $800 per household to help families purchase and install, for example, a new electric stove and … up to $1,600 per household to help families install new insulation. It means giving families up to $8,000 to replace their gas furnace” with a heat pump.
The funding connects “so many important priorities by helping families pay the upfront cost for energy efficiency upgrades to their homes,” Harris said. “We are also lowering energy bills, bringing down household costs, creating jobs and fighting the climate crisis.”
The rebate program could help to upgrade up to 1.6 million homes nationwide and install up to 500,000 heat pumps, according to a White House fact sheet. Harris estimated the savings per household at $500 a year; the Department of Energy said savings nationwide could reach $1 billion annually.
The DOE announcement provided more details on the funding, along with a list of allocations going to the states, ranging from more than $690 million for Texas to $59.4 million for the District of Columbia. Another $225 million is earmarked for a “high efficiency home rebate program” for tribal communities.
But those savings will likely not come this winter. Wednesday’s announcement allows states to “access information about their allocated funding and … begin planning programs to distribute relief to families, using these funds,” according to the White House.
The DOE release laid out a series of steps that will be taken prior to any actual distribution of funds. A series of “listening sessions” with states and “a wide array of stakeholders” will be held over the next three months, followed by a request for information early in 2023. DOE is targeting spring 2023 for getting the money to the states, with the public receiving rebates later in the year.
“States will have greater resources to meet their consumers’ needs and more rapidly achieve home electrification on the path to a net-zero emissions economy,” Energy Secretary Jennifer Granholm said in the release.
The rebate program is aimed at helping moderate- and low-income families with the upfront costs of energy efficiency improvements, Harris said.
The Details
The funding is divided between two programs: one providing home energy performance-based rebates and a second with rebates for high-efficiency home electrification, according to DOE.
For the performance-based rebates, homes that reduce energy use by 20% will be eligible for $2,000 in rebates, while a 35% cut in energy use will qualify for up to $4,000 in rebates. Those maximums will double for retrofits for low- and moderate-income households.
The rebates available for a high-efficiency electric home top out at $14,000 per household, with a $8,000 cap for a heat pump and $1,750 for a heat pump water heater, with all rebates paid at point of sale. Electric stoves and clothes dryers will also be eligible for rebates, as well as insulation and sealing measures.
The high-efficiency home rebates will also be based on family income relative to an area’s median income. A family earning 80% to 150% of the median income would qualify for rebates covering 50% of the cost of a specific upgrade, while households earning 80% or less of the median would receive a 100% rebate.
RACER
DOE also announced on Wednesday $43 million in funding for 23 projects that will “help communities plan their transition to a clean energy future and improve grid reliability and security.”
Most of the money will go to 20 projects under the Renewables Advancing Community Energy Resilience (RACER) program, which DOE said “seeks to enable communities to utilize solar and solar-plus-storage solutions to prevent disruptions in power caused by extreme weather and other events.”
For example, the Virginia Department of Energy is receiving $1 million for a project that “will identify opportunities to use distributed energy resources like solar-plus-storage in 10 different locations [in Southwestern Virginia] to maximize the benefits of energy resiliency infrastructure for disaster response needs.”
According to figures from the National Oceanic and Atmospheric Administration, the U.S. has sustained 15 extreme weather events with losses exceeding $1 billion each. Total costs are estimated at $30 billion, with “significant economic effects on the areas impacted,” DOE said.
The other three projects will focus on “building tools to help communities better evaluate and benefit from local energy resources,” DOE said. “Researchers will develop and share planning methodologies, tools, technologies and best practices that can be replicated in communities across the country as they work to install clean energy and strengthen grid infrastructure.”
“Knowledge is power, especially when it comes to giving local communities the tools to understand and make informed decisions about their own energy supply and needs,” Granholm said. “These critical projects will help deliver reliable, affordable energy to every pocket of America — strengthening the safety and resiliency of communities across the nation.”
Entergy on Wednesday said it is engaging with stakeholders as it prepares regulatory filings related to its proposed $15 billion, 10-year accelerated resilience plan to upgrade its system against future storm damage.
“We’ve invested in new infrastructure built to higher standards that will improve the system’s resilience,” CEO Drew Marsh told analysts during Entergy’s third-quarter conference call. “We expect our proposed investments to significantly reduce physical and financial storm risk.”
Marsh said the plan is “heavily informed” by Florida’s recent experience with Hurricane Ian.
“We did our homework,” the new CEO said. “Knowing that their hardened assets performed well in Hurricane Ian, along with the strong performance of our own hardened infrastructure over the past couple of years, gives us confidence that we can substantially reduce our exposure to storms and provide meaningful benefits to customers.”
The New Orleans City Council has already approved a $206 million securitization recovery for Entergy New Orleans’ Hurricane Ida costs and to replenish the company’s storm escrow. The company plans to file its resilience request in Louisiana by the end of the year and in Texas next year.
Entergy reported quarterly earnings of $561 million ($2.74/share), up from the same period a year ago when it delivered earnings of $531 million ($2.63). Marsh said the strong quarter allowed Entergy to cut 10 cents off its year-end adjusted earnings guidance, now $6.25 to $6.45.
The utility’s adjusted earnings of $2.84/share beat the Zacks Consensus Estimate of $2.67/share.
The earnings call was Marsh’s first as CEO. He replaced Leo Denault, who stepped down on Nov. 1 and continues to chair the company’s board. (See Entergy CEO Denault Stepping Down in 2023.)
CenterPoint Exceeds Expectations
CenterPoint Energy on Tuesday reported earnings of $189 million ($0.30/diluted share), a tick down from last year’s third quarter of $190 million ($0.32/diluted share).
The Houston-based company updated its capital expenditure plan by $2.3 billion to nearly $43 billion. CEO David Lesar said the incremental capital will be dedicated to further distribution system resilience, reliability and grid modernization, and transmission upgrades in its Houston Electric area.
CenterPoint’s adjusted earnings of 32 cents/share beat the Zacks Consensus Estimate of 31 cents, the 10th straight quarter Lesar’s management team has met or exceeded Wall Street’s expectations.
The company’s share price peaked at $28.93 on Tuesday before finishing at $28.11 on Wednesday, down 48 cents from its pre-announcement close.
ATLANTIC CITY, N.J. — PJM and the New Jersey Board of Public Utilities (BPU) are considering how to incorporate other states in future public policy transmission upgrades, an acknowledgement that the RTO’s State Agreement Approach could benefit “free riders,” officials told a conference Oct. 28.
The BPU voted Oct. 26 to award $1.07 billion in upgrades to deliver offshore wind generation to the PJM grid in the first application of the RTO’s State Agreement Approach. The SAA allows states to sponsor transmission to support their public policy needs while requiring them to pay 100% of the costs. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)
The BPU’s award will fund onshore transmission upgrades needed to integrate 6,400 MW of offshore wind, but it does not include any offshore transmission and further upgrades will be needed to meet the state’s new offshore wind goal of 11 GW. As a result, the BPU directed its staff to begin a second round of coordinated transmission planning to meet the increased goal, potentially including a new SAA solicitation.
One question that needs to be addressed is how to allocate costs for non-New Jersey projects that want to bring energy to the system through upgrades funded by New Jersey ratepayers, Kris Ohleth, executive director of the independent Special Initiative on Offshore Wind told the Time For Turbines conference in Atlantic City.
Ohleth, who moderated a panel before an audience of 125, described a situation in which “New Jersey is paying for this type of upgrade to our system, and the region benefits from offshore wind” projects using it.
BPU Executive Director Bob Brabston, who appeared on the panel with Asim Haque, PJM’s vice president of state and member services, said the BPU is just beginning to consider the free-rider issue raised by Ohleth.
“No one wants to pay for something that they’re not getting the benefit of,” Brabston said. “And we feel like there are a lot of benefits that will flow out of New Jersey because of this. But it’s really conceptual at this point. So, in terms of what that would really look like in terms of how complex cost allocation can be, and the different perspectives among our fellow member states, it’s really early to say how that might work out.”
Brabston echoed BPU General Counsel Abe Silverman, who said in September that state officials hope to engage in “horse trading” with other PJM states over the cost allocation of transmission needed to meet their climate goals. (See NJ Foresees ‘Horse Trading’ with Other PJM States over Tx Costs.)
PJM’s Haque said the cost allocation issue is part of a “robust discussion” underway in the industry about how it can be more proactive in addressing state transmission build-out needs. “Electrons don’t know state borders,” he said.
“We’re finding ourselves in a space where there are multiple states that are actually sort of sharing similar policy initiatives, whether it’s renewable portfolio standards or offshore wind initiatives,” he said. “Generally speaking, PJM is supportive of the sort of long-term, long-range transmission planning. And we’re supportive of thinking about how the states can get more involved in determining what cost allocation should look like.”
That’s complicated because states are at “different sort of points on the spectrum,” he said.
“You’ve got states in the PJM footprint that say that we, we don’t want to pay a dime for something that didn’t arise out of our state legislature, or an executive order or whatever,” he said. “And you have some states in the middle that said, ‘Well, let’s look at all the different benefits that would arise from this project. And if some benefits would eventually find a way to our consumers, we can conceivably pay for it.’ And you have states that say, ‘You know, there are so many states that with similar policy objectives, it makes sense for a lot of our states to go at it together and share costs.’”
Cost Reductions Through SAA
New Jersey’s process was the first time that any state has used the FERC-authorized SAA process, and conference speakers said the results demonstrate the benefits of the approach.
The BPU approved $504 million for work in and around the Larrabee substation in Central Jersey to FirstEnergy’s Jersey Central Power and Light and Mid-Atlantic Offshore Development (MAOD), a joint venture of Shell New Energies US (NYSE:SHEL) and EDF Renewables North America (OTCMKTS:ECIFY). The state also will spend $575 million for other upgrades to accommodate OSW generation.
BPU officials say that the $1.07 billion price tag is about $900 million lower than the upgrades would have been without the coordination and competitive bidding overseen by PJM under the SAA. PJM’s solicitation generated 80 proposals from 13 developers.
Without the coordinated process and competition the transmission upgrades needed would evolve through “many developers, many projects proceeding on their own timeline with their own decision making, their own priorities,” Brabston said. That could mean some benefits, such as “a lot of innovation and competition, but also a lot of duplication, no economies of scale, and a lot of impacts on communities and on the environment,” he said.
Although the BPU sought proposals for connections on and offshore, the BPU funded only onshore projects, leaving the offshore work still to be allocated. The board expects the winner of the third solicitation, which is due to take place early in 2023, to include plans for the offshore connections that will tie future projects to the upgraded transmission facilities just approved by the board.
“One of the aspects of the project that we awarded is the expectation that all of the cabling access that’s required for all of the offshore generation that we expect to award in future solicitations will come through the same landing point,” Brabston said. “And that’s a way that future developers will know with certainty where they need to come onshore, and that that particular asset will be there already constructed.”
Haque acknowledged that the SAA prompted PJM to change its own strategy.
“We weren’t always in the space of trying to figure out how to help states,” he said. “PJM was not always the most friendly to state policy endeavors. And so for us to have gone from a space where we had [BPU] President Fiordaliso say, ‘We may not be seeing eye to eye with PJM in the future’ to where we are now: We jointly figured out a path to build transmission to bring offshore wind to New Jersey consumers …. I think it’s really wonderful.”
Helping to De-Risk
John Dempsey, CEO of Blue Point Wind, a joint venture between EDP Renewables and Engie, which won the auction for an offshore wind development lease in the New York Bight in February, said the initiative would also help developers and the industry as a whole. Speaking on a panel that focused on OSW project developments off the New Jersey coast, he said the state’s SAA was a “tremendous, tremendous effort.”
The initiative “really goes a long way at helping de-risk projects, which lowers costs,” he said. “The efforts made by the state earlier in the week, I think really go a long way at making New Jersey a really good place for offshore wind developers to land, so we were really pleased to see that.”
Dempsey, in an email after the conference, said that as states increase their offshore wind capacity targets the industry will need more “proactive transmission development” like the BPU’s initiative to make projects happen.
Blue Point Wind, also known as Ocean Winds East, paid $765 million for its New York Bight lease, giving the developer rights to an ocean parcel 53 miles off the New Jersey Coast that is expected to generate 1,700 MW of electricity. The project will sell its power to either New York or New Jersey and is evaluating “multiple interconnection scenarios” at each location, Dempsey said.
“The BPU award offers clarity to the industry on the optimal cable landfall location and the point of interconnection for the next round of projects, and it will ensure that there is sufficient transmission capacity on the system to accommodate offshore wind,” he said. “For developers like Bluepoint Wind, this clarity will reduce uncertainties in their projects and allow them to offer more competitive proposals to New Jersey in its upcoming solicitations.”
Reliability risks from the addition of variable resources to the Western grid will continue to grow, requiring greater planning reserve margins to mitigate the unpredictability of wind and solar generation, WECC said Wednesday in its third annual Western Assessment of Resource Adequacy.
Last year’s Western assessment showed a planning reserve margin indicator (PRMI) for the Western Interconnection of 16.9%. The 2023 PRMI increased to 18.3% in WECC’s latest assessment.
“Additional [variable energy resources] will cause the PRMI to increase further,” WECC said. “If nothing is done to mitigate the long-term risks within the Western Interconnection, by 2025 we anticipate severe risks to the reliability and security of the interconnection.”
Power producers plan to retire 26 GW of resources, mostly coal and natural gas plants, during the next decade and to add 80 GW of new resources, most of which will be solar and wind generation and battery storage.
“The resource mix in 2032 will look different than it does today, with much higher levels of variability,” the assessment said. “This is because resources like solar and wind are variable, meaning their energy output changes constantly and there is limited dispatchability.”
Severe weather events and rising temperatures add to the uncertainty, as do electrification, energy efficiency and emerging technologies, WECC said.
All “will affect how demand looks and behaves over the next decade,” it said. “This added uncertainty exacerbates the challenges facing planners and operators.”
WECC’s other measure of resource adequacy, its demand-at-risk indicator (DRI), showed fewer hours at risk of electricity shortfalls in the next few years. WECC measures DRI for every hour of the year for five subregions: California and Mexico, the Desert Southwest and three regions — central, northwest and northeast — of the Western Power Pool (shown as NWPP in the report).
“Compared to the 2021 assessment, the DRI for the Western Interconnection decreases through 2025 due in part to reductions in the load forecasts in the Pacific Northwest and northern Rocky Mountains, and in part to actions taken after the 2020 heat wave to strengthen resource adequacy,” it said.
“These actions include the addition of almost 3,000 MW of new or expedited resources, the vast majority of which is battery storage, and the delayed retirement of generator resources,” WECC said.
The delayed retirements included the 2,300-MW coal-fired Jim Bridger Power Plant in Wyoming, the 1,600-MW gas-fired Haynes Generating Station in Long Beach, Calif., and the 830-MW gas-fired Scattergood Generating Station in Los Angeles.
“Once these plants are retired, the risk returns and will need to be mitigated,” WECC said. “Delaying the retirements provides entities more time to determine how to mitigate the risks once these plants retire.”
After 2025, each WECC subregion shows an increase in DRI because of retirements in the next decade, the reliability organization said.
WECC introduced its Western RA assessment in 2020 to supplement NERC’s Long-Term Reliability Assessment because Western stakeholders were concerned that NERC’s analysis did not capture all the risks the Western Interconnection faces.
Like the NERC assessment, WECC’s Western assessment attempts to identify the biggest threats to the bulk power system over the next 10 years.
WECC has scheduled two webinars to discuss its findings, a high-level policy overview on Nov. 9 and a “deep-dive technical review” on Nov. 16.
WASHINGTON — The nuclear industry is out to change the conventional wisdom on building new nukes — specifically that such projects are always late, over budget and do not perform as expected.
The way forward, according to a panel of nuclear safety regulators at the International Atomic Energy Agency’s Ministerial Conference last week, will require harmonization of standards, international collaboration and a strong sense of urgency.
“Regulators are often perceived as barriers to efficient deployment of new-build [projects] and the adoption of new technologies and innovation,” said Mark Foy, chief executive and chief nuclear inspector of the UK Office for Nuclear Regulation. “I think it’s time for regulators to actually bust that myth.”
Rumina Velshi, Canadian Nuclear Safety Commission | IAEA
With the U.K. targeting 24 GW of new nuclear by 2050, “the future will see innovative technologies, innovative operating regimes and new organizational designs,” Foy said in his opening remarks as both panel moderator and participant. “As [regulators], we welcome these and are beginning to look at our approach and criteria for assessment and for licensing, and how they need to evolve in this new world.”
“A global industry will require global solutions,” he said, with alignment — or “harmonization” — of standards between countries a major topic of discussion within the industry.
Rumina Velshi, CEO of Canada’s Nuclear Safety Commission, agreed that as new technologies such as small modular reactors (SMRs) are rolled out, countries will need to develop a common framework that is technology-inclusive, performance-based and risk-informed. Achieving the scale and speed needed to meet climate goals will also mean short-term standardization of SMR design, Velshi said.
“SMRs will only work if we’ve got a reasonable number of technologies, not the more than 80 or 90 being considered,” she said. “Governments and industry [must] come together with a reasonable set of technologies … and standard designs that can deploy globally.”
Christopher T. Hanson, NRC | IAEA
While agreeing with Velshi on the need for whittling down the “plethora of new designs,” Christopher T. Hanson, chair of the U.S. Nuclear Regulatory Commission, argued for striking “a balance between harmonization and sovereign, national responsibilities. After all, each of us regulators will be regulating the reactors within our own borders and are responsible to our citizens.”
The NRC in August issued a design certification for the NuScale SMR to be built at the Idaho National Laboratory and is now reviewing the Kairos Hermes advanced reactor planned for Tennessee, Hanson said. He also stressed the need for “the continued and ongoing safe operation of the current fleet, overseen by strong, technically competent and independent regulators.”
Liisa Heikinheimo, deputy director general of Finland’s Ministry of Economic Affairs and Employment, also talked about the need for speed and flexibility in permitting processes as nuclear technologies continue to evolve.
Finland has set an aggressive goal of 2035 for carbon neutrality, Heikinheimo said, and SMRs will be needed “not only for electricity production but also to produce heat. This is a new feature, and it should be understood well from different angles. We need to build, most probably, units closer to cities and to be more flexible in operations to be compatible with renewables.”
Lisa Heikinheimo, Finland | IAEA
Representing the industry voice on the panel, Jay Wileman, CEO of GE Hitachi Nuclear Energy, also called for a new narrative for nuclear, saying that the industry must counter its late and over-budget profile. The only new reactors built in the U.S. in three decades, Georgia Power’s Vogtle plants, are years late, with an estimated cost of $30 billon, more than double the original cost estimate of $14 billion. The utility announced that one of the reactors started to load fuel in October and could begin operation in the first quarter of 2023.
Moving forward, the industry must be more competitive, Wileman said. “We have to come in with a design that’s at the right cost. To do that, you have to have a standard plant, a repeatable one that can be taken globally from one country to another, one regulatory overview to another, without redesigning every time.”
“You have to design to cost,” and deliver both on time and on performance, he said.
GE Hitachi is working with regulators in the U.S. and Canada on the permitting for its BWRX-300 SMR, which has been chosen for projects by TVA, Ontario Power Generation and SaskPower in Saskatchewan.
Clean, Firm, Dispatchable
The emerging international footprint for nuclear is now, at least within the industry, a given. According to multiple speakers at the IAEA conference, keeping climate change to 1.5 degrees Celsius and achieving worldwide carbon neutrality by 2050 will not be possible without the clean, firm, dispatchable power nuclear can provide.
The change in attitudes toward nuclear around the world “is palpable,” said Rafael Mariano Grossi, director general of the IAEA, in his opening remarks at the event on Wednesday. “Countries, important countries, at some point in their contemporary history thought nuclear energy would no longer be part of their energy mix, and we see countries reversing those decisions or decisively moving into nuclear because we have to be led by science, by economically feasible decisions and not by ideology.”
With nations in Africa and Latin America increasingly looking at nuclear, Grossi said, governments must “choose the right technologies, the right partners and provide the right framework for nuclear expansion.”
William D. Magwood IV, director general of the Nuclear Energy Agency of the Organization for Economic Cooperation and Development (OECD), said nuclear generation — both for electricity and process heat for heavy industry — will have to triple by 2050.
Announcements during and following the conference add to a growing narrative around nuclear as a core technology for energy security and economic development in the U.S. and worldwide.
Energy Secretary Jennifer Granholm closed the conference on Friday with an announcement that Poland had selected a U.S. bid from Westinghouse for the country’s first nuclear reactor. The decision, Granholm said, “sends a clear message to Russia that the Atlantic alliance stands together to diversify our energy supply to strengthen climate cooperation and resist Russian weaponization of energy.”
On Thursday, TerraPower, the advanced nuclear company founded by Bill Gates, and PacifiCorp announced their plans to explore deploying TerraPower’s Natrium advanced reactor to five sites in the utility’s service territory by 2035. The two companies are collaborating on the federally funded Natrium demonstration plant being planned for Kemmerer, Wyoming, at the site of a coal plant slated for closure.
The White House on Monday also announced a new clean energy partnership with the United Arab Emirates, with the “full-scale implementation” of civil nuclear technology called out as a key provision of the partnership framework.
‘High-quality Inputs’
While the U.S. continues to lead the world in nuclear power generation, China has moved into second place with 54 reactors currently in operation and another 22 under construction, according to the World Nuclear Association. As with other clean technologies, China has also developed a strong domestic supply chain, putting pressure on U.S. competitiveness in international markets.
Regulators at the IAEA conference faced questions about how long safety permitting should take and what companies and regulators need to do to keep projects on track.
Hanson said the length of the permitting cycle “depends on the quality of the input — if we have substantive pre-application engagement, if we get high-quality inputs. What does ‘high-quality inputs’ mean? It means show your work. Don’t just assert safety, show us; prove it in your application.”
Complexity and maturity of technology are other key factors, he said. One recent application, for a low-power reactor used to produce isotopes at a medical facility in Wisconsin, was reviewed in 24 months, Hanson said,
The NRC also recently released the draft environmental impact statement for the Kairos Hermes advanced reactor, 12 months after the project was first submitted. A final EIS is scheduled for the end of September 2023, according to the NRC website.
Velshi said Canada is also aiming for a 24-month turnaround for new advanced reactors.
At the same time, license extensions have become a major focus for U.S. and Canadian regulators, with projects in both countries looking to extend plant life to 60 or even 80 years. In the U.S., the NRC looks for “a rigorous and data-focused aging management plan … to ensure that as that plant proceeds into its longer life, it is doing so safety,” Hanson said.
The refurbishments needed for relicensing are often “massive projects that are probably equivalent to new-build projects,” Velshi said. The nuclear sector’s ability to deliver these projects on time and safely can provide “remarkable value in building confidence” for the public, investors and policy makers, she said.
Wileman agreed with the regulators on the need for high-quality applications, but he said, companies like GE Hitachi need “very good pre-submission discussions … really being able to go shoulder-to-shoulder and work the process collaboratively and make sure the dialogue is there; make sure everyone has a sense of urgency.”
“It’s important that the regulators and the industry understand the ambitions of one another and perhaps the challenges that each [faces],” Foy said. “But you can’t do it in isolation. You do have to come together and work on that end solution.”
PROVIDENCE, R.I. — ISO-NE’s Board of Directors had the rare experience of staring public criticism in the face on Tuesday as the grid operator held its first open board meeting at a Renaissance Hotel in downtown Providence, R.I.
A series of speakers offering public comments came up one by one, addressed the board and told them what they think ISO-NE is doing wrong.
Most of the roughly 15 commenters were there to push ISO-NE to transition more quickly off fossil fuels and take the climate crisis seriously.
The meeting came about as part of a set of governance changes the grid operator is making to appease the New England states, which have been pushing for it to become more transparent and accessible. (See ISO-NE Offers up Governance Tweaks)
One of the most attention-grabbing comments came from Kendra Ford, a Unitarian Universalist minister from Exeter, N.H., who walked to the microphone and looked into the eyes of each of the board members before speaking.
“We are in an emergency, and you are not acting like this is an emergency. We have to rearrange and reorganize the way we think about everything. Energy is at the leading edge of that,” Ford told the board.
“You have done some things, but you need to do so much more, and you need to do it immediately to save lives,” she said.
Later, as the board continued its largely standard business with an update from ISO-NE CEO Gordon van Welie, Ford stood up again and cut in.
“You’re describing a carefully measured, convenient transition that doesn’t inconvenience anyone and doesn’t cause anyone to lose money. That can no longer be the way,” she said. “I am begging you to respond to the emergency. It may not be affecting you personally in this moment, but it is coming to all of us.”
Another commenter, Jonas Kaplan-Bucciarelli, a Boston University student from Amherst, Mass., asked the board to walk a mile in his shoes.
“I think that you don’t understand the level of urgency and despair around the climate crisis, especially that my generation is experiencing as we’re growing up in this world, and grew up having climate change on the radar as we were going through middle school and elementary school,” he said.
Many of the commenters spoke out against the region’s minimum offer price rule, which ISO-NE is phasing out instead of immediately removing, to the frustration of climate advocates in the region.
They also took ISO-NE to task for a stakeholder process that’s widely seen as the least accessible of any grid operator in the country.
“It’s been a struggle to engage with you all,” said Amanda Nash, an activist with No Coal No Gas and 350 Massachusetts.
“You are all well trained and paid to create and administrate these procedures, but for the vast majority of us, this is work we do on top of our jobs and other responsibilities,” Nash said. “It seems like obfuscation is the name of the game.”
ISO-NE COO Vamsi Chadalavada offered a response to the commenters later in the meeting.
“The passion and urgency that we heard is unmistakable,” he said. “But I also wanted to offer some comfort that that’s the same level of urgency that all of us at the ISO feel in making sure we get through the clean energy transition.”
“I didn’t want to leave you with an impression that we are pro-fossil. … We are equally motivated to move towards the future,” Chadalavada said.
And he urged people to reach out to the ISO for information and to answer questions, technical or otherwise.
At the meeting, van Welie gave a presentation on the organization’s strategic plan, and the grid operator’s managers also updated the board on market projects, energy adequacy and winter planning. And MIT Energy Initiative director Robert Armstrong gave a presentation to the board on the future of energy storage.
Champlain Hudson Power Express said Tuesday it has closed on the financing needed to build its roughly $6 billion underground transmission line linking Quebec and New York City.
All major permits for the 340-mile U.S. portion of the 1,250-MW transmission line are in place, and construction will begin this fall in New York, CHPE said. Government permits for the 36-mile Canadian portion of the project are anticipated in summer 2023, and completion is projected in spring 2026.
Along with construction costs, the project price tag includes tens of millions of dollars for community benefit projects over the next several decades.
“The project financing announced today is an important step toward starting construction and beginning to realize the tremendous economic and environmental benefits this project will provide to residents, organizations and municipalities throughout the state,” Donald Jessome, CEO of TDI-USA Holdings, CHPE’s parent, said in a news release Tuesday. “We look forward to watching our community partners move forward with vital projects that will improve the communities they live and work in, and to soon begin delivering clean, renewable energy to New York City.”
CHPE has been in the works for more than a decade: It was first proposed in 2010, and it received approval from the New York Public Service Commission in 2013.
It is an important part of the state’s decarbonization strategy, as it will bring more than 1 GW of zero-emission hydroelectric power to a region that now relies heavily on fossil-generated electricity.
Dominion Energy (NYSE:D) on Friday filed a settlement agreement with the Virginia attorney general and other stakeholders that proposes an alternative to the performance requirement ordered by the State Corporation Commission (SCC) for the company’s $9.8 billion Coastal Virginia Offshore Wind (CVOW) project.
The group proposes to replace a 42% capacity performance guarantee, imposed by the SCC as a condition of its approval of the project, with a process through which the company explains any capacity shortfalls and the commission determines remedies. The company would be required to “provide a detailed explanation of the factors contributing to any deficiency” causing the project’s net capacity factor to fall below 42% on a three-year rolling average. The commission would then determine whether the shortfall “resulted from the unreasonable or imprudent actions of the company” and could impose a remedy addressing incremental energy or other costs.
Dominion CEO Robert Blue had called the performance mandate “untenable” and said it would require the company “to financially guarantee the weather, among other factors beyond its control, for the life of the project.” In an Aug. 22 petition for reconsideration, the company said it could be forced to terminate all development of the project if the requirement was not lifted. (See Dominion CEO: SCC Order for OSW Performance Guarantee ‘Untenable’.)
“Given the now significantly de-risked status of the project’s development, and given its continued ‘on-budget’ status, we feel that this settlement reflects a balanced sharing of financial impacts in what we currently see as unlikely scenarios of material delays or cost overruns,” Blue said in a statement on the agreement, which included the Sierra Club, Walmart (NYSE:WMT)
and environmental advocacy organization Appalachian Voices.
University of Virginia environmental law professor Cale Jaffe, who worked with Sierra on the settlement, said the proposed agreement addresses their concerns with the performance guarantee by leaving the door open to a precedent being set for fossil fuel generators being subject to the same requirements that offshore wind may be held to. He noted that Dominion’s Wise County coal plant has been operating well below its estimated capacity factor and has been steadily declining, leaving ratepayers with a large capital cost.
“We were very concerned about asymmetric treatment between new renewable energy … and older fossil fuel generation. … So one point we wanted to make sure was to raise concerns of any asymmetric treatment of renewable resources as compared to fossil,” he said.
The proposal would also avoid the possibility of making the project so onerous as to make development impossible, he said, which would come into conflict with the statutory demands of the Virginia Clean Economy Act, which is explicit in designating that CVOW is in the public interest.
The agreement, however, would not resolve Sierra’s original concern in the project: ensuring that the development considers the historically disadvantaged communities of Hampton Roads. Jaffe said the club will continue pushing for those interests to be included in Dominion’s economic plan, in the form of considering local and minority-owned businesses for hiring employees.
“There would be roughly 900 construction jobs, another 1,100 operation jobs … and we wanted to make sure diversity, equity, and inclusion was a part of that,” Jaffe said.
Agreement Includes ‘Unprecedented Consumer Protections’
In a statement on the filing, Attorney General Jason Miyares said the agreement includes “unprecedented consumer protections for Virginians” with cost sharing on project overruns and a cost cap on construction expenses.
“I am pleased that we have achieved consumer protections never seen before in modern Virginia history. For the first time, Dominion has significant skin in the game to ensure that the project is delivered on budget. Should the project run materially overbudget, it will come out of Dominion’s pocket, not consumers’,” Miyares said.
Under the proposed cost-sharing arrangement, customers would pay the first $500 million of costs above $9.8 billion, followed by an even split for the following $1 billion. Any costs above $11.3 billion will be paid entirely by Dominion; though if the project rises above $13.7 billion, it would go before the SCC to make a determination of viability and potential further cost allocation.
“This cost-sharing and cost-cap agreement means that Dominion will potentially have to pay almost $3 billion if the project runs over budget. Ensuring that the project remains on budget is crucial to ensuring it is also built on time,” Miyares said.
The agreement also states that Dominion “shall take all reasonable steps to ensure that customers receive the full and complete benefits of the Inflation Reduction Act of 2022” and not make any elections under the legislation that would reduce the benefit to customers. It also stipulates that if the completed project produces less than 2,587 MW, the cost-sharing schedule would also decrease on a per-megawatt prorated basis.
Dominion said work has continued to keep the project on schedule, which calls for construction to be complete in late 2026, and 90% of costs are expected to be fixed by the end of the first quarter of next year, up from 75% currently.
“The settlement agreement provides a balanced and reasonable approach that supports continued investment in CVOW to meet the commonwealth’s public policy and economic development priorities and the needs of Dominion Energy Virginia’s 2.7 million customers representing more than 5 million people and businesses,” the company said.
Appalachian Voices Virginia Policy Director Peter Anderson said the proposal creates an alternative to the SCC order for controlling the project’s construction risks and bringing down the presumption of reasonable costs ratepayers could be responsible for in the event of overruns. He also believes the agreement balances the interests of all the parties involved in the development, particularly by ensuring that the company bears some risk alongside customers.
“At this point it’s up to the commission as to whether they think it’s in the best interests of ratepayers,” he said.
California’s statewide greenhouse gas emissions dropped 8.7% in 2020, a “historic” decline that’s largely due to the impact of the COVID-19 pandemic, according to a new report.
The data are included in “California Greenhouse Gas Emissions for 2000 to 2020,” a greenhouse gas inventory released last week by the California Air Resources Board (CARB).
CARB said the drop in GHG emissions in 2020 was the largest percentage decrease in the more than two decades that the state has been tracking GHG emissions. Previously, the largest decline occurred between 2008 and 2009, when GHG emissions fell 6% during the Great Recession.
In 2019, the state’s GHG emissions fell 1.7%, following an increase of less than 1% in 2018. (SeeCalif. GHGs Decline 1.7% in 2019.)
The “historic plummet in emissions” in 2020 was due to the pandemic, according to CARB, which cautioned the public to view the results as an outlier.
“Economic recovery from the pandemic may result in emissions increases over the next few years,” CARB said in its report. “As such, the total 2020 reported emissions are likely an anomaly, and any near-term increases in annual emissions should be considered in the context of the pandemic.”
Transportation Emissions
California’s 2020 GHG emissions totaled 369.2 million metric tons (MMT) of CO2 equivalent (CO2e), 35.3 MMT less than 2019 levels.
When analyzed by sector, the largest decline was in transportation, which saw a 16% decrease in GHG emissions or a drop of 27 MMT of CO2e. Transportation remained the largest contributor to the state’s GHG inventory, accounting for 37% of the total.
CARB said the 16% decrease in transportation emissions was likely due to shelter-in-place orders issued in 2020 and an associated decrease in driving.
Other factors are the 18% growth during 2020 in the number of battery electric vehicles in the state and increases in fuel-efficiency of vehicles. In addition, heavy-duty trucks are using an increasing percentage of bio- and renewable diesel fuel, which accounted for 21% of diesel fuel sold in the state in 2020.
GHG emissions also decreased in the industrial sector, with a drop of 7 MMT of CO2e, or 9%. Decreased emissions from oil and gas production, as well as refining and hydrogen production, contributed to the sector’s results.
In the commercial and residential sector, GHG emissions fell by 1.7 MMT, which CARB attributed to a relatively warm winter and a slowdown in commercial activity due to the pandemic.
Electricity Sector
One sector that did not see a substantial drop in GHG emissions in 2020 was electricity, which remained near 2019 levels of about 60 MMT of CO2e. That’s 16% of the state’s total emissions.
GHG emissions from California’s electricity sector. | CARB
Emissions from in-state generation increased in 2020, CARB said, as more natural gas was used to make up for reduced availability of hydropower. But emissions from electricity imported from outside of California fell in 2020, as the state continued a trend of importing a greater share of low-GHG electricity.
In another likely impact of the pandemic, the state’s gross domestic product (GDP) fell by about 2.8% during 2020. But GHG emissions per GDP unit decreased in California that year by 6.1%, which CARB said “demonstrat[es] the effectiveness of California’s long-term climate programs to decarbonize industry, energy and transportation.”
The state’s GHG emissions per capita also fell in 2020, dropping to 9.3 metric tons of CO2e per person compared to 13.1 metric tons per person in 2006.
California Assembly Bill 32 of 2006 set a target of reducing the state’s GHG emissions to 1990 levels by 2020. The state previously reported meeting that goal four years early, in 2016. GHG emissions in 1990 were 431 MMT.
But while preparing the latest edition of the GHG inventory, CARB discovered and corrected a “data discrepancy” that affected past years’ figures, the agency said. The revised data show that the state hit the AB 32 target in 2014 rather than 2016, according to CARB.
California still must meet a more stringent target set by Senate Bill 32 of 2016. The bill requires a reduction of GHG emissions to 40% below 1990 levels by 2030.
In addition, a draft climate change scoping plan that CARB released this year sets a statewide goal of carbon-neutrality by 2045. (See Critics Tear into CARB Draft Climate Change Plan.) The agency expects to finalize the plan by the end of the year.
